In the recovery of hydrocarbons from subterranean formations it is common practice, particularly in formations of low permeability, to fracture the hydrocarbon-bearing formation to provide flow channels. These flow channels facilitate movement of the hydrocarbons to the wellbore so that the hydrocarbons may be pumped from the well.
In such fracturing operations, a fracturing fluid is hydraulically injected into a wellbore penetrating the subterranean formation and is forced against the formation strata by pressure. The formation strata or rock is forced to crack and fracture, and a proppant is placed in the fracture by movement of a viscous fluid containing proppant into the crack in the rock. The resulting fracture, with proppant in place, provides improved flow of the recoverable fluid, i.e., oil, gas or water, into the wellbore.
Fracturing fluids customarily comprise a thickened or gelled aqueous solution which has suspended therein "proppant" particles that are substantially insoluble in the fluids of the formation. Proppant particles carried by the fracturing fluid remain in the fracture created, thus propping open the fracture when the fracturing pressure is released and the well is put into production. Suitable proppant materials include sand, walnut shells, sintered bauxite, or similar materials. The "propped" fracture provides a larger flow channel to the wellbore through which an increased quantity of hydrocarbons can flow, thereby increasing the production rate of a well.
A problem common to many hydraulic fracturing operations is the loss of fracturing fluid into the porous matrix of the formation. Fracturing fluid loss is a major problem. Hundreds of thousands (or even millions) of gallons of fracturing fluid must be pumped down the wellbore to fracture such wells, and pumping such large quantities of fluid is very costly. The lost fluid also causes problems with the function or technique of the fracture. For example, the undesirable loss of fluid into the formation limits the fracture size and geometry which can be created during the hydraulic fracturing pressure pumping operation. Thus, the total volume of the fracture, or crack, is limited by the lost fluid volume that is lost into the rock, because such lost fluid is unavailable to apply volume and pressure to the rock face.
Hydraulic fracturing fluids usually contain a hydratable polymer which thickens the fracturing fluid when it is chemically crosslinked. Such a polymer typically is hydrated upon the surface of the ground in a batch mix operation for several hours in a mixing tank or other container, and crosslinked over a period of time to viscosify the fluid so that it is capable of carrying the proppant into the fracture. Natural polymers including polysaccharides, such as guar, have been used in this way.
One problem associated with the use of polysaccharides as viscosifiers for fracturing fluids is that the hydration and crosslinking process is time consuming and requires expensive and bulky equipment at the wellsite. Such equipment, and the asociated personnel to operate it, significantly increase the cost of the fracturing operation. Further, once the polysaccharide is hydrated and crosslinked, it is not feasible to add additional polysaccharide to the solution, or to regulate the concentration of polysaccharide in the fracturing fluid in real time during the pumping of the job.
Another difficulty is that a large number of supplementary additives are required to use polysaccharides successfully, including for example: bactericides, antifoam agents, surfactants to aid dispersion, pH control agents, chemical breakers, enzymatic breakers, iron control agents, fluid stabilizers, crosslinkers, crosslinking delay additives, antioxidants, salt(s) and the like. These materials must be formulated correctly (which can be a difficult task), transported to the jobsite, and then pumped and metered accurately during the execution of the fracturing treatment.
Another disadvantage associated with such polysaccharide based fracturing fluids is that, when they are used as viscosifiers, they contain materials that concentrate in the formation during the course of the hydraulic fracturing treatment, reducing the production of hydrocarbons after the fracturing event. For example, during the course of a treatment, water from the fracturing fluid leaks into the formation leaving the polysaccharide behind. Guar concentrations in the fracture sometimes increase by as much as a factor of twenty as compared to the concentration of guar in the actual fracturing fluid.
Many fracturing fluid materials, therefore, when used in large concentrations, have relatively poor "clean-up" properties, meaning that such fluids undesirably reduce the permeability of the formation and proppant pack after fracturing the formation. Detailed studies of polysaccharide recovery in the field after hydraulic fracturing operations indicate that more than sixty percent of the total mass of polysaccharide pumped during the treatment maybe left in the fracture at the time gas or oil begins to be produced in commercial quantities. Poor clean-up is a problem.
Well productivity after fracturing increases dramatically as the amount of polysaccharide returned to the surface increases. Anything that reduces the permeability of the propped fracture to hydrocarbons is usually detrimental to the production of hydrocarbons from the well.
Other polysaccharides, such as hydroxyethylcellulose ("HEC") are sometimes believed to provide improved clean-up as compared to polysaccharide based materials; however, HEC is known to form undesirable clumps or "fish eyes" during mixing. Further, HEC is limited to lower formation temperatures, and thus is not preferred for a wide variety of fracturing conditions.
To overcome the limitations of fracturing with natural or synthetic polysaccharides, some have suggested using relatively expensive materials as viscosity enhancers, such as viscoelastic surfactants. Fluids prepared from such materials are capable of carrying proppant into a fracture, but do not have many of the limitations of polysaccharide materials. Viscoelastic surfactants form micelles that are able to proceed into the reservoir rock, and then break up, allowing the components to be removed. Therefore, breaker materials are not customarily required, which reduces cost and improves cleanup of the fluid from the formation.
The problems encountered with viscoelastic surfactant based fluids in the past, however, include relatively large fluid losses into formations in which they have been used. Micellar-type viscoelastic fluids have not been utilized widely in fracturing treatments of relatively low permeability formations because, among other reasons, materials have not been available that would enable the maintenance of a desired viscosity at temperatures above about 130.degree. F., which is less than the temperature at which most hydraulic fracturing operations are conducted.
Until recently, the use of such viscoelastic surfactant fluids has been restricted largely to operations in shallow, high permeability to control sand production either in conventional gravel packing operations or involving fracturing very close to the wellbore, such as in so called "frac-and-pack" type operations. The cost of viscoelastic components has rendered them too expensive, in most cases, to utilize in normal fracturing treatments of a large size and high volume.
Use of viscoelastic surfactant fracturing fluids has been limited in many cases to formations that contain clays or otherwise need soluble salts for the specific purpose of inhibiting hydration of the clay materials. If such clay materials are allowed to hydrate, problems can occur, thus the need exists for a soluble salt that can inhibit the hydration of such clay-type materials. U.S. Pat. No. 5,551,516 to Norman et al. ("Norman") discloses generally fracturing stimulation of high permeability formations, and more specifically, the use of surfactant based fracturing fluids. However, Norman does not teach this invention, and in particular, application to low permeability formations. Further, Norman teaches the use of an organic activator, such as, for example sodium salicylate, which is not required in this invention.
Notably, low permeability formations present different fluid loss control challenges that typically are not addressed in fluids designed to work on high permeability formations. For example, solid fluid-loss-control additives, which are very effective in high permeability formations, have little or no utility in hydrocarbon zones of low permeability.
U.S. Pat. Nos. 4,725,372 and 4,615,825 (collectively "Teot") specifically teaches and defines fluids used in treating the wellbore. This requires the use of heavy brines (e.g. greater than 12-15 lbs/gallon of brine). Heavy brines generally are not desirable in hydraulic fracturing of low permeability formations. Heavy brines can minimize fluid returns after the hydraulic fracturing treatment, adversely affecting cleanup and well productivity.
For example, fluid systems that operate effectively in ammonium chloride salts many times are frequently not compatible with much heavier calcium chloride, calcium bromide and zinc salt derived brines that typically are required for wellbore treatments. Therefore, fluids of a viscoelastic type designed for wellbore applications have not been directly useful in the past as reservoir treating fluids (sand control, acid fracturing, hydraulic fracturing, matrix acidizing, remedial scale inhibition treatments and the like) and vice-versa.
A need exists for a surfactant fluid that economically can increase hydrocarbon production, limit connate water production, resist fluid loss into the formation, and preserve the component balance of the fluid mixture. A fluid that can achieve the above while improving the precision with which fluids are delivered, and reduce equipment or operational requirements, would be highly desirable.